Well system

ABSTRACT

A drilling system includes a work string supporting a bottom hole assembly. The work string including lengths of pipe having a non-metallic portion. The work string preferably includes a composite umbilical having a fluid impermeable liner, multiple load carrying layers, and a wear layer. Multiple electrical conductors and data transmission conductors are embedded in the load carrying layers for carrying current or transmitting data between the bottom hole assembly and the surface. The bottom hole assembly includes a bit, a gamma ray and inclinometer instrument package, a propulsion system with resistivity antenna and steerable assembly, an electronics section, a transmission, and a power section for rotating the bit. The electrical conductors in the composite umbilical provide power to the electronics section and may provide power to the power section. The data transmission conduits in the composite umbilical transmit the data from the downhole sensors to the surface where the data is processed. The propulsion system includes two or more traction modules connected by rams disposed in cylinders for walking the bottom hole assembly up and down the borehole. The propulsion system includes a steerable assembly, controlled from the surface, for changing the trajectory of the borehole.

CROSS-REFERENCE TO RELATED APPLICATION

The present application claims the benefit of 35 U.S.C. 119(e)provisional application Ser. No. 60/063,326, filed Oct. 27, 1997 andentitled Drilling System, incorporated herein by reference.

BACKGROUND OF THE INVENTION

The present invention relates to a system using a work string forperforming a downhole operation in a well and more particularly includesa bottom hole assembly disposed on a composite umbilical made up of atube having a portion thereof which is preferably non-metallic. In usingthe well system for drilling the well, the bottom hole assembly includesa power section for rotating a bit and a propulsion system for movingthe bottom hole assembly within the well.

Many existing wells include hydrocarbon pay zones which were bypassedduring drilling and completion because such bypassed zones were noteconomical to complete and produce. Offshore drilling rigs costapproximately $40 million to build and may cost as much as $250,000 aday to lease. Such costs preclude the use of such expensive rigs todrill and complete these bypassed hydrocarbon pay zones. Presently,there is no cost effective methods of producing many bypassed zones.Thus, often only the larger oil and gas producing zones are completedand produced because those wells are sufficiently productive to justifythe cost of drilling and completion using offshore rigs.

Many major oil and gas fields are now paying out and there is a need fora cost effective method of producing these previously bypassedhydrocarbon pay zones. The locations and size of these bypassedhydrocarbon zones are generally known, particularly in the more matureproducing fields.

To economically drill and complete the bypassed pay zones in existingwells, it is necessary to eliminate the use of conventional rigs andconventional drilling equipment. One method of producing wells withoutrigs is the use of metal coiled tubing with a bottom hole assembly. Seefor example U.S. Pat. Nos. 5,215,151; 5,394,951 and 5,713,422, allincorporated herein by reference. The bottom hole assembly typicallyincludes a downhole motor providing the power to rotate a bit fordrilling the borehole. The bottom hole assembly operates only in thesliding mode since the metal coiled tubing is not rotated at the surfacelike that of steel drill pipe which is rotated by a rotary table on therig. The bottom hole assembly may include a tractor which propels thebottom hole assembly down the borehole. One such tractor is a thrusterthat pushes off the lower terminal end of the coiled tubing and does notrely upon contacting or gripping the inside wall of the borehole. Thedepth that can be drilled by such a bottom hole assembly is limited.

One such self-propelled tractor is manufactured by Western Well Tool forpropelling a near conventional bottom hole assembly in the borehole. Thepropulsion system includes an upper and lower housing with a packerfootmounted on each end. Each housing has a hydraulic cylinder and ram formoving the propulsion system within the borehole. The propulsion systemoperates by the lower packerfoot expanding into engagement with the wallof the borehole with the ram in the lower housing extending in thecylinder to force the bit downhole. Simultaneously, the upper packfootcontracts and moves to the other end of the upper housing. Once the ramin the lower housing completes its stroke, then the hydraulic ram in theupper housing is actuated to propel the bit and motor further downholeas the lower packerfoot contracts and resets at the other end of thelower housing. This cycle is repeated to continuously move the bottomhole assembly within the borehole. The tractor can propel the bottomhole assembly in either direction in the borehole. Flow passages areprovided between the packerfeet and housings to allow the passage ofdrilling fluids through the propulsion system.

Various companies manufacture self-propelled tractors for propelling thebit and pulling steel coiled tubing in the well. These tractors includeself-propelled wheels that frictionally engage the wall of the borehole.However, there is very little clearance between the wheels of thepropulsion system and the wall of the borehole and problems arise whenthe wheels encounter ridges or other variances in the dimensions of thewall of the borehole. Further, at times there is an inadequatefrictional engagement between the wheels and the wall of the borehole toadequately propel the tractor.

Other companies also offer tractors to walk the end of a wireline down acased borehole. However, these tractors engage the interior wall of acasing having a known inside dimension. One such tractor is manufacturedby Schlumberger.

The use of metal coiled tubing has various deficiencies. Metal coiledtubing tends to buckle the deeper the bottom hole assembly penetratesthe borehole. Buckling is particularly acute in deviated wells wheregravity does not assist in pulling the tubing downhole. As the tubingbuckles, the torque and drag created by the contact with the boreholebecomes more difficult to overcome and often makes it impractical orimpossible to use coiled tubing to reach distant bypassed hydrocarbonzones. Further, steel coiled tubing often fatigues from cyclic bendingearly in the drilling process and must be replaced. It has also beenfound that coiled tubing may be as expensive to use as a conventionaldrilling system using jointed steel pipe and a rig.

The bottom hole assembly may also include an orienting tool such as abent sub or housing for directing the trajectory of the borehole. Sometypes of orienting tools may be adjusted from the surface. Often, priorart orienting tools require a 360° rotation to ratchet to a newdirection of inclination.

The bottom hole assembly may include various sensors such as a gamma rayand inclinometer instrument package adjacent the bit and a multipledepth dual frequency borehole compensated resistivity tool. These toolsproduce data indicating the inclination and azimuth of the bit and theposition of the bottom hole assembly with respect to the formation. Thebottom hole assembly may also include other sensors for providing otherdata relating to the borehole, such as gyroscopic survey data,resistivity measurements, downhole temperatures, downhole pressures,flow rates, velocity of the power section, gamma ray measurements, fluididentification, formation samples, and pressure, shock, vibration,weight on bit, torque at bit, and other sensor data.

Prior art bottom hole assemblies for rotary drilling and for use withmetal coiled tubing include electronic components for collecting data,processing the data downhole, and transmitting the processed informationto the surface. The processed information may be transmitted to thesurface either by conventional wirelines or by mud pulsed telemetry. Inmud pulsed telemetry, the processed information is pulsed back to thesurface through the mud column using a valve which opens and closes toproduce the pulses. See U.S. Pat. No. 5,586,084. The transmission ratefor mud pulsed telemetry, however, is limited.

The electronic components in the bottom hole assembly are also limitedin the temperature that they can withstand. Once the environment of theelectronic components is subjected to high temperatures, such as 305° F.or greater, for any extended period of time, some of the electroniccomponents may stop functioning. Thus, electronic components, such assemiconductor chips, must be carefully produced and selected to ensurethat they can withstand the anticipated heat, shock, and vibration ofthe bottom hole assembly. Since the life of the electronic components isa function of temperature over time, the higher the downholetemperature, the shorter the life of the electronic components. Thus,not only are the electronic components expensive, but the complexity ofthe equipment for processing the data downhole causes the bottom holeassemblies to be very expensive particularly for logging while drilling.Such electronic components also reduces the reliability of the bottomhole assembly.

In drilling new boreholes from existing wells to produce bypassed zones,it is often necessary to cut an aperture or window in the existingcasing followed by a drilling string passing through the window to drilla deviated borehole into the bypassed zone. Prior art tools used incutting the window in the existing casing produce a window of erraticgeometry and often with an irregular shape. Also, the cutting tool tendsto produce a jagged edge around the periphery of the window. Oftentimessuccessive trips are required into the borehole to clean up the windowbefore the new deviated wellbore may be drilled. The irregular shape andjagged edge can cause problems in drilling the new borehole andcompleting the well. Since the specific location and geometry of thewindow is unknown, it is also difficult to establish a seal between thecasing in the existing borehole and the new casing in the new borehole.

The prior art procedures for sealing the cased borehole with the newcasing include filling the gaps between the irregularly shaped windowand new casing with cement during the cementing operation. Specialcement that is very plastic is often required for flowing into thesegaps. Oftentimes the end of the casing must be milled clean. Also oftenthe gaps remain around the window even after the cementing operationsuch that the cement still may not provide an adequate seal.

The present invention overcomes the deficiencies of the prior art.

SUMMARY OF THE INVENTION

The system of the present invention uses the unique properties of acomposite umbilical to extend the reach of bottom hole assemblies intodeviated and horizontal subterranean boreholes to over twice and as manyas 5 to 10 times the reach previously accomplished by prior art systems.The apparatus used in the inventive system is lighter and more compactthan that of other prior art systems including existing tubulars andrigs. The complexity and cost of moving, lifting and installing theinventive system and the space and structural strength required todeploy it are minimal compared to prior art oil and gas rotary drillingrigs or metallic coiled tubing units.

The system of the present invention preferably includes a compositeumbilical having a inner fluid impermeable liner, multiple load carryinglayers, and an outer wear layer. The load carrying layers are preferablyresin fibers braided around the inner liner. Multiple electricalconductors and data transmission conductors are embedded in the loadcarrying layers for carrying electric current and transmitting databetween the bottom hole assembly and the surface. Also, a plurality ofsensors may be mounted on one or more of the data transmission conduitsalong the length of the composite umbilical.

The bottom hole assembly includes a bit, a gamma ray and inclinometerand azimuth instrument package, a propulsion system with steerableassembly, an electronics section, a resistivity tool, a transmission anda power section for rotating the bit. The electrical conductors in thecomposite umbilical provide power to the electronics section and mayprovide power to the power section. The data transmission conduits inthe composite umbilical may be fiber optic cables which transmit to thesurface the data from various sensors such as the gamma ray andinclinometer instrument package and resistivity tool.

The propulsion system includes a housing having an upstream section witha traction module and a downstream section with a traction module. Thetraction modules are each connected to a ram mounted in a cylinderwithin one of the housing sections for propelling the bottom holeassembly up and down the borehole. In operation, one of the tractionmodules expands to engage the borehole while the hydraulic ram forcesthe bit downhole and pulls the umbilical forward and the other tractionmodule moves to the other end of its housing section in preparation foractuating its ram to move the bit farther downhole. The housing of thepropulsion system includes a flow bore through which may extend anoutput shaft operatively connected to the power section on one end andto the bit on the other end. The steerable assembly may be of varioustypes for changing the trajectory of the well such as an adjustablecoupling between the two housing sections, a three dimensional,adjustable diameter blade stabilizer mounted on the housing of thepropulsion system, or two multi-positional traction modules mounted onthe housing of the propulsion system which can individually extendeccentrically. When the steerable assembly is an adjustable coupling,the output shaft through the propulsion system has an articulated jointat the mating of the two housing sections.

The drilling system may also include an alternative bottom hole assemblyfor cutting a window in an existing cased borehole. The bottom holeassembly is connected to a composite umbilical and includes an upstreamand downstream traction module for straddling that portion of the casedborehole in which the window is to be cut. A template is mounted on thehousing of the assembly and is hydraulically or electrically actuatedinto engagement with the inside wall of the cased borehole. A cuttingnozzle is mounted on a geared track on the housing to cut the window inthe casing as defined by the template. The cut pieces of the casing arethen retracted magnetically by electromagnets and retained in thehousing. Once the window has been cut, the bottom hole assembly andpieces of casing are removed from the well. A tubular member with a sealflange is then mounted on a bottom hole assembly. The assembly is runback into the borehole and the tubular member with seal flange isinstalled in the window. A production string is then run into the welland mounted within the tubular member for producing the bypassedformation. The seal flange seals the connection.

The drilling system also includes a method and apparatus for settingpipe in the new borehole without the use of a rig. Casing rams are usedto install the production string in the well.

One advantage of the drilling system of the present invention is thedrilling of wells without using a drilling rig. The drilling system maybe operated from a vessel and use a subsea drilling template. However,no rig, jack up, or floater is required. The drilling system of thepresent invention is a rigless umbilical drilling system and can be usedfor not only reentering existing wells but also for drilling new wells.

Another advantage of the drilling system of the present invention is thesignificant reduction of the number of crew required to operate thesystem.

A further advantage is the use of a non-metallic drill string. Theelimination of steel work strings enables the elimination of a drillingrig otherwise required to handle metal pipe.

A further advantage of the drilling system of the present invention isthe use of a composite umbilical which extends from the bottom holeassembly to the surface. The use of composite umbilical providesenhanced pressure control at the surface since making and breaking ofsteel tool joints are eliminated. Also, there is a substantially reducednumber of upsets on the composite umbilical as compared to steel drillpipe which would otherwise have to pass through the blowout preventer.The composite umbilical is reeled into the borehole to the extentpossible and then it is further deployed by a downhole umbilicalpropulsion system. The composite umbilical is then retrieved by reelingthe composite umbilical onto a reel at the surface.

Another advantage of the composite umbilical of the present invention isthat the multiple lengths of pipe do not have to be connected anddisconnected at the surface to the same extent as required for jointedsteel drill pipe using rigs.

A further advantage of composite umbilical is the ability to drill andcomplete the well at near balance or under balanced. By drilling andcompleting the well at near balance with the fluid column pressureapproximately the same as the formation pressure, less damage is causedto the producing formation.

Another advantage of the present invention is the use of a bottom holeassembly which is anchored to the borehole thus minimizing much of thevibration encountered by conventional bottom hole assemblies. Vibration,harmonics and shock are very damaging to conventional bottom holeassemblies and particularly the electronic components in suchassemblies.

Another advantage of the present invention is the use of electricalconductors extending through the composite umbilical. By conductingelectrical power between the surface and the bottom hole assembly,alternators and batteries are no longer required in the bottom holeassembly to operate the electronic components.

A further advantage of the present invention is the use of datatransmission conduits, such as fiber optic cable or coaxial cable,passing through the wall of the composite umbilical. Such datatransmission conductors allow the transmission of raw data received bythe sensors in the bottom hole assembly for transmission directly to thesurface without exposing the wire which could then be damaged. The datathen can be processed at the surface rather than downhole such as in aconventional bottom hole assembly. By processing the data at thesurface, larger and more sophisticated and less expensive computerprocessing systems may be used for analyzing the data. Further, theelectronics required in conventional bottom hole assemblies forprocessing the data downhole may be eliminated thereby reducing the costof expensive and somewhat fragile downhole electronic components. Astill another advantage of using data transmission conduits in thecomposite umbilical is the ability to transmit the data directly to thesurface faster and with greater reliability. The conventional process ofpulsing the data through the mud column to the surface is eliminated.

Another advantage of the present invention is the use of connectors forconnecting lengths of composite umbilical including the connection ofthe electrical and data transmission conduits.

A further advantage of the present invention is the use of an efficient,reliable and less expensive downhole umbilical propulsion system andsurvey system for accurate directional drilling.

Other objects and advantages of the present invention will appear fromthe following description.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of a preferred embodiment of the invention,reference will now be made to the accompanying drawings wherein:

FIG. 1 is a schematic of an elevation view of the drilling system of thepresent invention in a typical drilling application for a well;

FIG. 2 is a cross-section view of the composite umbilical of the presentinvention;

FIG. 3 is a cross-sectional view taken of plane 3—3 in FIG. 2 of thecomposite umbilical having electrical conductors and data transmissionconductors;

FIG. 4 is a cross-sectional view of a connector connecting two lengthsof composite umbilical;

FIG. 5 is a schematic of an elevation view of the bottom hole assemblyof the present invention connected to the downstream end of thecomposite umbilical;

FIG. 5A is a schematic of a transmission having an integral counterrotation device for the bottom hole assembly of FIG. 5;

FIG. 6 is a cross-sectional view of the propulsion system withresistivity antennas and a steerable assembly;

FIG. 7 is a cross-sectional view taken at plane 7—7 in FIG. 6 showingone of the traction modules;

FIG. 8 is a schematic elevation view, partly in cross-section, of analternative embodiment of the bottom hole assembly for cutting a windowin an existing cased borehole;

FIG. 9 is a cross-sectional elevation view of the window being cut inthe existing cased borehole of FIG. 8;

FIG. 10 is a schematic of a cross-sectional view of the window of FIGS.8 and 9 with a production string installed in the new borehole;

FIG. 11 is a schematic of a system for installing and removing steelpipe in a new borehole;

FIG. 12 is an exploded view of a casing ram for deploying and retrievinga joint of casing into the new borehole;

FIG. 13 is a schematic cross-section view of a propulsion system havingan alternative steerable assembly for use with the present invention;

FIG. 14 is a cross section view taken at plane 14 in FIG. 13 of thetraction module;

FIG. 15 is a schematic cross-section view of a propulsion system havinganother alternative steerable assembly for use with the presentinvention;

FIG. 16 is a cross section view taken at plane 16 in FIG. 15 of thesteering actuator for the steerable assembly of FIG. 15; and

FIG. 17 is a graph comparing pull forces versus mud weight on compositean steel coil tubing.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention is susceptible to embodiments of different forms.There are shown in the drawings, and herein will be described in detail,specific embodiments of the present invention with the understandingthat the present disclosure is to be considered an exemplification ofthe principles of the invention, and is not intended to limit theinvention to that illustrated and described herein.

The system of the present invention includes a composite umbilicalhaving a bottom hole assembly attached. Various embodiments of thepresent invention provide a number of different constructions of thebottom hole assembly, each of which is used for a downhole operation inone of many different types of wells including a new well, an extendedreach well, extending an existing well, a sidetracked well, a deviatedborehole, and other types of boreholes. It should be appreciated thatthe bottom hole assembly may be only a downhole tool for performing anoperation downhole in the well. Often the downhole operation relates tothe drilling and completing of a pay zone in the well but the presentinvention is not limited to such operations. The embodiments of thepresent invention provide a plurality of methods for using the system ofthe present invention. It is to be fully recognized that the differentteachings of the embodiments discussed below may be employed separatelyor in any suitable combination to produce desired results in a downholeoperation. In particular the present system may be used in practicallyany type of downhole operation.

Referring initially to FIG. 1, there is shown a schematic for using thesystem of the present invention as a drilling system, generallydesignated 10. The drilling system 10 includes a string of pipe forminga work string 20 with a bottom hole assembly 30 connected to its lowerend. The work string 20 and bottom hole assembly 30 are shown disposedin a sidetracked well 12 which deviates from an existing well 14. Thedrilling system 10 extends from the floor 16 of an existing platform 18previously used to drill, complete, and produce existing well 14.Various controls 21 are disposed at the surface on the platform 18 forreceiving and sending signals downhole. Such controls are well known inthe art. It should be appreciated that blowout preventers and otherrequisite safety control equipment 22 would be disposed on platformfloor 16 for drilling and completing well 12. It should also beappreciated that the sidetracked well 12 is merely exemplary fordescribing the drilling system 10 and its operation in a typicalapplication of the present invention and should in no way be consideredas limiting the present invention to sidetracked wells.

A composite umbilical 20 serves as the work string. The operativesalient properties of the composite umbilical are a tube having an axialcomponent of the modulus of elasticity with a Young's modulus in therange of 500,000 to 10,500,000 psi. The preferred range of Young'smodulus is from 2,000,000 to 5,000,000 psi. The tube is non-isotropicand the modulus of elasticity is not the same in all axes nor is itlinear. Embodiments of the pipe may be constructed of fibers such asnonmetallic fibers, metallic fibers, or a mixture of nonmetallic andmetallic fibers. One embodiment includes a tube constructed fromhelically wound or braided fiber reinforced thermoplastic or fiberreinforced thermosetting polymer or epoxy. The fiber may be non-metallicor metallic or a mixture of metallic and non-metallic materials. Thecomposite umbilical preferably is made of a material having a densitywith a specific gravity in the range of 0.99 grams per cubic centimeterto 2.9 grams per cubic centimeter. Unless defined otherwise, the termcomposite umbilical as used in the present application shall mean acontinuous spoolable or segmented and connected tubular string havingthe characteristics set forth above. It should be appreciated thatalthough the pipe described above for the present invention does notinclude coiled tubing, various components of the present invention maybe adapted for use with coiled tubing particularly with short reachwells and with smart tractors.

The composite umbilical 20 with the above characteristic provides manyadvantages. The low modulus of elasticity permits a large tube to bereeled onto a small diameter spool without yielding the material of theumbilical 20. The tube does not fatigue in bending. The lower modulusmay allow an indefinite fatigue life of the umbilical from coiling onthe spool. Further, the lower modulus provides a very low drag when theumbilical is forced around short radius bends and curvatures in theborehole as the umbilical goes in and out of the well. The low densityallows the tube to be light weight for transporting and lifting. Alsothe tube can be made buoyant in the wellbore by using an appropriatelyweighted mud or by specifically engineering the tube. A 12.9 pound pergallon mud achieves a neutral buoyancy of the tube in the most preferredgeometry. Having a buoyancy close to the weight of the drilling fluidsallows a minimum frictional drag on the borehole wall due to gravity asthe umbilical moves in and out of the borehole.

The following is a comparison of bending strain between steel andcomposite coiled tubing:

For 2⅞″ steel tubing; typical yield stress θ_(y)=80,000 psi

Therefore the yield strain ε_(y)=θ_(y)/E where E is the Young's Modulusof the material.

Since E_(steel)=30×106 psi, then, ε_(y(steel))=80000/30000000=0.00267in/in

In the same manner; E_(composite)=1.43×10⁶ psi; and typicallyθ_(y(composite))=26000 psi

Therefore, ε_(y(composite))=26000/1430000=0.01818 in/in

The maximum bending strain before yielding composite pipe is 6.81 timeshigher than for steel. For bending calculation, see “Mark's StandardHandbook for Mechanical Engineers,” Baumeister, Theodore, Avallone,Eugene A., Baumeister, Theodore III, Eighth Edition, McGraw-Hill BookCompany, New York, 1978, pg. 5-54, incorporated herein by reference.

The following provides a comparison of the forces required to pulleither steel or composite coiled tubing illustrating the ability of asystem with a downhole propulsion system and composite umbilical to movedeeper into the borehole and to be retrieved from the borehole.

The force needed to pull either steel or composite coil tubing toovercome simple sliding friction is:

The pull force required for steel tubing (F_(steel)):

F_(steel)=μ*W_(steel)*K_(steel)*L_(steel)

Where, μ=coefficient of friction of wellbore (assume 0.5)

W_(steel)=weight per foot of steel=4.53 lb/ft (2⅞″ OD×{fraction (5/16)}″wall)

K_(bst)=buoyancy factor for steel in 12.5 ppg mud =0.809

L_(steel)=length of pipe in horizontal=10000 ft.

Therefore, the force required to pull 10000 ft. of steel is:

F_(steel)=18,324 lbs.

In the same manner for composite;

μ=coefficient of friction of wellbore (assume 0.5)

Wcomposite₁=weight per foot of composite=1.7 lb/ft (2⅞″ OD×{fraction(5/16)}″ wall)

K_(bcomposite)=buoyancy factor for composite in 12.5 ppg mud=0.0157

L_(composite)=length of pipe in horizontal=10000 ft.

Therefore, the force required to pull 10000 ft. of composite is:

F_(composite)=133 lbs.

The force required to pull 10000 ft. of steel pipe is 138 times greaterthan the force required to pull the same amount of composite pipe. Forfriction calculation, see “Mark's Standard Handbook for MechanicalEngineers,” Baumeister, Theodore, Avallone, Eugene A., Baumeister,Theodore III, Eighth Edition, McGraw-Hill Book Company, New York, 1978,pg. 3-24 to 3-27, incorporated herein by reference.

Referring now to FIG. 17, there is shown a graph comparing the pullforces needed to drill a 50,000 foot lateral well using either compositeor steel coil tubing under different buoyancy conditions, i.e. differentmud weights.

Referring now to FIGS. 2 and 3, the tube for umbilical 20 is preferablyof a composite material having the characteristics described above.Composite umbilical 20 preferably has an impermeable fluid liner 32, aplurality of load carrying layers 34, and a wear layer 36. As best shownin FIG. 3, a plurality of conductors 40, 42 are embedded in the loadcarrying layers 34. These conductors may be metallic or fiber opticconductors, such as electrical conductors 40 and data transmissionconductors 42. One or more of the data transmission conduits 42 mayinclude a plurality of sensors 44. It should be appreciated that theconductors may be passages extending the length of umbilical 20 for thetransmission of pressure fluids.

Types of composite tubing are shown and described in U.S. Pat. Nos.5,018,583; 5,097,870; 5,176,180; 5,285,008; 5,285,204; 5,330,807;5,348,096; and 5,469,916, each of these patents is incorporated hereinby reference. See also “Development of Composite Coiled Tubing forOilfield Services,” by A. Sas-Jaworsky and J. G. Williams, SPE Paper26536, 1993, incorporated herein by reference. U.S. Pat. Nos. 5,080,175;5,172,765; 5,234,058; 5,437,899; and 5,540,870, each of these patentsbeing incorporated herein by reference, disclose composite rods,electrical or optical conductors housed in a composite cable.

The impermeable fluid liner 32 is an inner tube preferably made of apolymer, such as polyvinyl chloride or polyethylene. Liner 32 can alsobe made of a nylon, other special polymer, or elastomer. In selecting anappropriate material for fluid liner 32, consideration is given to thechemicals in the drilling fluids to be used in drilling the sidetrackedwell 12 and the temperatures to be encountered downhole. The primarypurpose for inner liner 32 is as an impermeable fluid barrier sincecarbon fibers are not impervious to fluid migration particularly afterthey have been bent. The inner liner 32 is impermeable to fluids andthereby isolates the load carrying layers 34 from the drilling fluidspassing through the flow bore 46 of liner 32. Inner liner 32 also servesas a mandrel for the application of the load carrying layers 34 duringthe manufacturing process for the composite umbilical 20.

The load carrying layers 34 are preferably a resin fiber having asufficient number of layers to sustain the required load of the workstring 20 suspended in fluid, including the weight of the compositeumbilical 20 and bottom hole assembly 30. For example, the umbilical 20of FIG. 2 has six load carrying layers 34.

The fibers of load carrying layers 34 are preferably wound into athermal setting or curable resin. Carbon fibers are preferred because oftheir strength, and although glass fibers are not as strong, glassfibers are much less expensive than carbon fibers. Also, a hybrid ofcarbon and glass fibers may be used. Thus, the particular fibers for theload carrying layers 34 will depend upon the well, particularly thedepth of the well, such that an appropriate compromise of strength andcost may be achieved in the fiber selected. Typically an all carbonfiber is preferred because of its strength and its ability to withstandpressure.

Load carrying fibers 34 provide the mechanical properties of thecomposite umbilical 20. The load carrying layers 34 are wrapped andbraided so as to provide the composite umbilical 20 with variousmechanical properties including tensile and compressive strength, burststrength, flexibility, resistance to caustic fluids, gas invasion,external hydrostatic pressure, internal fluid pressure, ability to bestripped into the borehole, density i.e. flotation, fatigue resistanceand other mechanical properties. Fibers 34 are uniquely wrapped andbraided to maximize the mechanical properties of composite umbilical 20including adding substantially to its strength.

The wear layer 36 is preferably braided around the outermost loadcarrying layer 34. The wear layer 36 is a sacrificial layer since itwill engage the inner wall of the borehole 12 and will wear as thecomposite umbilical 20 is tripped into the well 12. Wear layer 36protects the underlying load carrying layers 34. One preferred wearlayer is that of Kevlar™ which is a very strong material which isresistant to abrasion. Although only one wear layer 36 is shown, theremay be additional wear layers as required. One advantage of wear layer36 is that one can be of a different fiber and color making it easy todetermine the wear locations on composite umbilical 20. It should beappreciated that inner liner 32 and wear layer 36 are not critical tothe use of composite umbilical 20 and may not be required in certainapplications. A pressure layer 38 may also be applied although notrequired.

During the braiding process, electrical conductors 40, data transmissionconductors 42, sensors 44 and other data links may be embedded betweenthe load carrying layers 34 in the wall of composite umbilical 20. Theseare wound into the wall of composite umbilical 20 with the carbon,hybrid, or glass fibers of load carrying layers 34. It should beappreciated that any number of electrical conductors 40, datatransmission conduits 42, and sensors 44 may be embedded as desired inthe wall of composite umbilical 20.

The electrical conductors 40 may include one or more copper wires suchas wire 41, multi-conductor copper wires, braided wires such as at 43,or coaxial woven conductors. These are connected to a power supply atthe surface. A braided copper wire 43 or coaxial cable 45 is wound withthe fibers integral to the load carrying layers 34. Although individualcopper wires may be used, a braided copper wire 43 provides a greatertransmission capacity with reduced resistance along composite umbilical20. Electrical conductors 40 allow the transmission of a large amount ofelectrical power from the surface to the bottom hole assembly 30 throughessentially a single conductor. With multiplexing, there may be two-waycommunication through a single conductor 41 between the surface andbottom hole assembly 30. This single conductor 41 may provide datatransmission to the surface.

The principal copper conductor 40 used for power transmission from thepower supply at the surface to the bottom hole assembly 30 is preferablybraided copper wire 43. The braided cooper wire 43 may be used toprovide the power for power section 90 which rotates the bit 140.Braided copper wire 43 may conduct a large voltage, such as 400 volts ofelectricity, from the surface which will generate heat which must bedissipated. Braided copper wire 43 is preferably disposed between thetwo outermost load carrying layers 34. By locating braided copper wire43 adjacent the outer diameter of composite umbilical 20, the braidedcopper wire 43 is disposed over a greater surface area of layers 34 tomaximize the dissipation of heat.

The data transmission conduit 42 may be a plurality of fiber optic datastrands or cables providing communication to the controls at the surfacesuch that all data is transmitted in either direction fiber optically.Fiber optic cables provide a broad band width transmission and permittwo-way communication between bottom hole assembly 30 and the surface.As previously described, the fiber optic cable may be linear or spirallywound in the carbon, hybrid or glass fibers of load carrying layers 34.

As shown in FIG. 3, sensors 44 are embedded in the load carrying layers34 and connected to one or more of the data transmission conductors 42such as a fiber optic cable. As an alternative to embedded sensors, thefiber optic cable may be etched at various intervals along its length toserve as a sensor at predetermined locations along the length ofcomposite umbilical 20. This allows the pressures, temperatures andother parameters to be monitored along the composite umbilical 20 andtransmitted to the controls at the surface.

Composite umbilical 20 is coilable so that it may be spooled onto adrum. In the manufacturing of composite umbilical 20, inner liner 32 isspooled off a drum and passed linearly through a braiding machine. Thecarbon, hybrid, or glass fibers are then braided onto the inner liner 32as liner 32 passes through multiple braiding machines, each braiding alayer of fiber onto inner liner 32. The finished composite umbilical 20is then spooled onto a drum.

During the braiding process, the electrical conductors 40, datatransmission conductors 42, and sensors 44 are applied to the compositeumbilical 20 between the braiding of load carrying layers 34. Conductors40, 42 may be laid linearly, wound spirally or braided around umbilical20 during the manufacturing process while braiding the fibers. Further,conductors 40, 42 may be wound at a particular angle so as to compensatefor the expansion of inner liner 32 upon pressurization of compositeumbilical 20.

Composite umbilical 20 may be made of various diameters. Although a 1½inch diameter is typically used for metal coiled tubing, compositeumbilical 20 preferably has a diameter greater than 1½ inches. The sizeof umbilical, of course, will be determined by the particularapplication and well for which it is to be used.

Although it is possible that the composite umbilical 20 may have anycontinuous length, such as up to 25,000 feet, it is preferred that thecomposite umbilical 20 be manufactured in shorter lengths as, forexample, in 1,000, 5,000, and 10,000 foot lengths. A typical drum willhold approximately 12,000 feet of composite umbilical. However, it istypical to have additional back up drums available with additionalcomposite umbilical 20. These drums, of course, may be used to add orshorten the length of the composite umbilical 20. With respect to thediameters and weight of the composite umbilical 20, there is nopractical limitation as to its length.

Composite umbilical 20 has all of the properties requisite to enable thedrilling and completion of extended reach wells. In particular,composite umbilical 20 has great strength for its weight when suspendedin fluid as compared to ferrous materials and has good longevity.Composite umbilical 20 also is compatible with the drilling fluids usedto drill the borehole and approaches buoyancy (dependent upon mud weightand density) upon passing drilling fluids down its flowbore 46 and backup the annulus 82 formed by the borehole 12. This reduces to acceptablelimits drag and other friction factors previously encountered by metalpipe. Composite umbilical 20 may be used in elevated temperaturesparticularly when a heat exchanger is placed on drilling platform 16 tocool the drilling fluids circulating through the borehole 12. Since thecomposite umbilical 20 is not rotated to rotate bit 140, no torque isplaced on composite umbilical 20.

Referring now to FIG. 4, there is shown a connector 50 for connectingadjacent lengths 52, 54 of composite umbilical 20. A jet sub 60 may bedisposed in connector 50 as hereinafter described. Connector 50 includesa female end connector 56 mounted on composite umbilical length 52 and amale end connector 58 mounted on composite umbilical length 54.Describing end connector 58 in detail, end connector 58 includes an endface 59, an outside tubular housing 62 and an inner tubular skirt 64forming an annular area 66 for receiving a plurality of load carryinglayers 34. As can be seen, inner liner 32 extends through inner tubularskirt 64. One or more pins 68 extend through housing 62, load carryinglayers 34, and inner skirt 64 for connecting end connector 58 to theterminal end of composite umbilical length 54. Other types of connectorsare shown in U.S. Pat. Nos. 4,844,516 and 5,332,049, both incorporatedherein by reference.

A plurality of connectors 70 are provided in the end face 59 of endconnector 58 for connection to electrical conductors 40 and datatransmission conductors 42 housed between load carrying layers 34.Connectors for fiber optic cables are described in U.S. Pat. Nos.4,568,145; 4,699,454; and 5,064,268, all incorporated herein byreference. A connector for coaxial cable is shown in U.S. Pat. No.4,698,028, incorporated herein by reference. For electrical conductorsin tubing, see U.S. Pat. No. 5,146,982, incorporated herein byreference. Another type of fiber optic connector is manufactured by DeanG. O'Brien of California.

Connector 50 is a quick connect connector. One type of quick connectionis the bayonet type connection shown in FIG. 4. The male end connector58 includes a plurality of arcuate segments 72 having a outwardlyprojecting tapered surface 74 adapted for mating with female connector56 having a plurality of arcuate segments 76 with an inwardly directedand tapered flange 78. In operation, the segments on male end connector58 are inserted between the segments 76 on end connector 56 and then endconnector 58 is rotated with tapered surfaces 74, 78 drawing the two endfaces 57, 59 of end connectors 56, 58 together. The end face of femaleend connector 56 includes a plurality of high pressure sealing members79 which sealingly engage the end face 59 of male end connector 58. Uponfull engagement of end connectors 56, 58 to form connector 50, theconnectors 70 for electrical conductors 40 and data transmissionconductors 42 are in alignment and are connected for transmission ofelectrical current or data.

It should be appreciated that an apparatus may be used on the platformfloor 16 for connecting connector 50. One such apparatus may include avise for that end of the length of the composite umbilical 20 extendinginto the well 12 and a tong for the end of the new length of compositeumbilical 20 whereby the tong inserts and rotates the new length to formthe connection 50.

It should be appreciated that end connectors 56, 58 are preferablymounted on the ends of composite umbilical 20 during the manufacturingprocess and therefore are already mounted on the ends of umbilical 20upon transport to the drilling site. It should also be appreciated thatthe end connectors 56, 58 need not be made of metal but may be made of acomposite. A composite end connector could be heat bonded to the end ofcomposite umbilical 20. Also, it should be appreciated that other typesof quick connections could be used such as the type of quick connectionused for high pressure hose connections.

One alternative to the individual connectors 64, 66 for conductors 40,42 are communication links which electro-magnetically transmit signalsaround the connections rather than go through connector 50. See U.S.Pat. No. 5,160,925, incorporated herein by reference. It is preferred,however, for the conductors 40, 42 to be directly connected together atconnection 50.

Connectors, comparable to connector 50, are used to connect thedownstream end of composite umbilical 20 to the bottom hole assembly 30and to the electrical systems at the surface for providing electricalpower and for processing the data. The connectors 50 will also be usedto repair a damaged end of composite umbilical 20 such that the damagedend may be cut off and the remainder reconnected to the work string 20.It is preferred that custom lengths of composite umbilical 20 not bemade for each well.

Referring now to FIG. 5, bottom hole assembly 30 is shown connected tothe down stream end 78 of composite work string 20 by a release tool 80.Release tool 80 is preferably connected to one of the conductors 40, 42for electrical actuation from the surface. Various types of releasetools may be used as release tool 80, such as an explosive charge, achemical cutter, or a mechanical release. One type of mechanical releasefor releasing metal coiled tubing is disclosed in U.S. Pat. No.5,146,984, incorporated herein by reference. The preferred release tool80 includes a charge detonated electrically to sever the connectionbetween bottom hole assembly 30 and work string 20. Such a release toolis simple and reliable. Release tool 80 is required should bottom holeassembly 30 get stuck in the well 12.

The bottom hole assembly 30 shown in FIG. 5 is used for drilling theborehole 12 and includes a power section 90, a surface controlledtransmission 100, an integral counter rotation device 125, anelectronics section 110, a downhole umbilical propulsion system 120, aresistivity tool 121, a steerable assembly 124, a gamma ray andinclinometer instrument package 130 and a bit 140 mounted on drill stem123. The power section 90 provides the power for rotation of bit 140.The propulsion system 120 provides the motive force to walk the bottomhole assembly 30 in or out of the borehole 12. It should be appreciatedthat the composite umbilical 20 cannot be pushed into the borehole. Thepropulsion system 120 can pull the composite umbilical 20 into theborehole or it can be used to back the composite umbilical out of theborehole. Resistivity tool 121 determines the formation resistivityaround the bottom hole assembly 30 and includes a resistivity antenna122 housed in propulsion system 120 and an electronics package housed inelectronics section 110. Steerable assembly 124 changes the trajectoryof the borehole 12 and is preferably housed in propulsion system 120.The gamma ray and inclinometer instrument package 130 evaluates thecharacteristics of the formation at the bit 140 and provides earlyinformation about the orientation and angle control of the bit 140within the borehole 12.

It should also be appreciated that the bottom hole assembly 30 mayinclude a concentric adjustable stabilizer such as that disclosed inU.S. Pat. No. 5,332,048, incorporated herein by reference. Thestabilizer may be disposed anywhere on bottom hole assembly 30 dependingupon the application.

It should be appreciated that the make up of bottom hole assembly 30will vary with the application and well. Examples of other tools thatmay be added to bottom hole assembly 30 include an NMR magneticresonance imaging tool for transmitting data to the surface indicatingvarious characteristics of the fluids in the surrounding formationincluding their transportability, identification, and composition. Itshould also be appreciated that different types of sensors may beincluded in the electronic section 110 or located elsewhere on bottomhole assembly 30 for providing other information concerning drilling andthe formation such as tri-axial accelerometers and inclinometers fordirectional control and surveying. For example, all of the parametersand characteristics that are determined with logging while drilling maybe included in bottom hole assembly 30. Other parameters andcharacteristics from sensors include operating pressures, operatingtemperatures, annular pressure, formation pressure, pressure sampling,fluid identification, gyroscopic surveying, porosity, and density.

The power section 90 may be one or a combination of power sourcesincluding a hydraulic drive, an electric drive, a turbine, a vane typemotor, or any other downhole motor for powering bit 140. The powersection 90 may change its torque or RPM characteristics and can becontrolled from the surface.

One typical power section 90 includes a downhole hydraulic motor usingconventional positive displacement for rotating the output shaft. Themotor has a rotor and stator with the rotor rotating as hydraulic fluidspass down through composite umbilical 20 and between the rotor andstator in the power section 90. The rotor is connected to an outputshaft which feeds into the surface controlled transmission 100. Powerfrom the transmission 100 is transmitted to the bit 140 by means of arotating shaft which may include one or more constant velocity joints. Adownhole drilling motor is disclosed in U.S. Pat. No. 5,620,056,incorporated herein by reference.

It should be appreciated that the electrical conductors 40 of compositeumbilical 20 extending to the surface allow the power section 90 toinclude one or more electric motors. Current may be conducted from thesurface to operate a multi-stage electric motor as power section 90.Such a multi-stage motor has the ability to supply the requiredperformance characteristics at the drill bit 140. Multi-stage motors arealso rugged, reliable and can be sealed from drilling fluids.

It should be appreciated that even though non hydraulic motors may beused as power section 90, drilling fluids are still passed down theflowbore 46 of composite umbilical 20 and up the outer annulus 82 formedby borehole 12 and composite umbilical 20 to remove the cuttings of thedrill bit 140 and to cool and lubricate the bit 140 and other componentsof bottom hole assembly 30.

Surface controlled transmission 100 may be used and is mounted on thedownstream end of power section 90 to vary and adjust the performancecharacteristics of the power section 90. The transmission 100 alters theproperties of the power output from power section 90 such as changingtorque and/or RPM characteristics. Depending upon the type of power usedin power section 90, transmission 100 may or may not be used andincludes a gear reduction or gear increase. Referring now to FIG. 5A,transmission 100 preferably also includes a integral counter rotationdevice 125 which can be controlled from the surface and allow forreverse rotation of the propulsion system 120. The integral counterrotation device 125 includes a connection 111 between the transmission100 and propulsion system 120 and a motor 113 for providing relativerotation between the stationary transmission 100 and the propulsionsystem 120. The integral counter rotation device 125 is used to allowcounter rotation of the propulsion system 120 to maintain the correctorientation of the bend angle of the steerable assembly 124 on thepropulsion system 120 if the propulsion system 120 has been rotatedslightly out of proper orientation due to reactive torque. It shouldalso be appreciated that a motor could also be adapted to rotate the bit140 in a direction opposite to that of the power section 90.

The electronics section 110 provides the electronics package andinstrumentation for measurements, logging, and pay zone steering whiledrilling. The electronics section 110 includes the electronics packagefor the resistivity tool 121 and is connected to resistivity antenna 122in propulsion system 120. Tools measuring resistivity are shown in U.S.Pat. Nos. 5,233,522; 5,235,285; 5,260,662; 5,339,036; and 5,442,294, allincorporated herein by reference. The electronics section 110 serves asa formation measuring tool.

Referring now to FIGS. 6 and 7, the downhole umbilical propulsion system120 serves multiple purposes including the thrusting or propulsion ofthe bottom hole assembly 30 in either direction, the resistivitymeasurements of the surrounding formation, and the steerable assembly124 for pay zone steering the borehole trajectory. Propulsion system 120includes a housing 106 which has a flow bore 114 therethrough for thedrilling fluids flowing down through flowbore 46 of composite umbilical20. It should be appreciated that there must be sufficient flow area toobtain adequate down hole flow and yet maintain sufficient wallthickness in housing 106.

For self-propulsion, propulsion system 120 becomes the prime mover andincludes a downstream packer-like traction module 102 and an upstreampacker-like traction module 104. It should be appreciated that thepropulsion system 120 may include more than two traction modules.Housing 106 of propulsion system 120 includes a downstream section 108and an upstream section 112 and is approximately 20 feet long with eachof the housing sections 108, 112 being approximately 10 feet long. Apower output shaft 116 extends through central flowbore 114 and mayinclude an articulation joint 118 adjacent the center of propulsionsystem 120 depending upon the type of steering assembly 124 being used.

As best shown in FIG. 7, there is shown a cross-section of tractionmodule 102. Since traction modules 102, 104 are similar in construction,a description of one traction module approximates the description of theother. Traction module 102 includes steel feet 96 around its outercircumference which may be expanded and contracted into engagement withthe wall of borehole 12. A plurality of flutes or longitudinal fluidflow passages 98 are provided around the inner circumference of thesteel bands forming feet 96 to allow drilling fluid to flow upstreamthrough annulus 82 when traction module 102 is expanded into engagementwith the wall of borehole 12. Traction modules 102, 104 may haveindependently inflatable, individual chambers, as hereinafter describedin detail, for expanding modules 102, 104 eccentrically with respect tothe housing 106.

Downstream housing section 108 includes a tubular cylinder 126 in whichis disposed a hydraulic rain 128 on which is mounted downstream tractionmodule 102. Hydraulic ports 135, 132 are disposed at the opposite endsof tubular cylinder 126 for applying hydraulic pressure to ram 128.Hydraulic ports 134, 136 are disposed adjacent downstream tractionmodule 102 for expanding and contracting the traction module in and outof engagement with the wall of borehole 12. It should be appreciatedthat upstream housing section 112 is similar in construction andoperation. It should also be appreciated that propulsion system 120includes a series of valves using fluid pressure for the actuation oftraction modules 102, 104 and rams 128, 129 mounted on traction modules102, 104, respectively.

The cycle of propulsion system 120 includes expanding downstreamtraction module 102 into engagement with the interior of borehole 12with the upstream traction module 104 in the contracted and non-engagedposition. Hydraulic pressure is applied through hydraulic ports 135applying pressure to ram 128. As pressure is applied against ram 128which is stationary due to its attachment to engaged traction module102, housing 106 moves down hole driving bit 140 forwardly upstream.Hydraulic fluid is simultaneously applied through hydraulic port 133causing contracted upstream traction module 104 to move forward onupstream housing section 112. Upstream traction module 104 moves forwardsimultaneously with housing 106 moving downhole and actuating the bit140. Once the downstream traction module 102 reaches the upstream end oftubular cylinder 126, it has completed its forward stroke and iscontracted. Simultaneously, upstream traction module 104 has nowcompleted its travel to the downstream end of tubular cylinder 127 andit is in its reset position to start its downward stroke of bit 140.Traction module 104 is then expanded into engagement with borehole 12.As hydraulic pressure is applied through hydraulic port 131 and againstupstream ram 129, propulsion system 120 strokes downwardly against bit140. Simultaneously, downstream traction module 102 is contracted andreset by applying hydraulic pressure through upstream port 132. Thecycle is then repeated allowing the propulsion system 120 to movecontinuously downstream in one fluid motion and provide a downwardpressure on drill bit 140. Each stroke approximates the length ofhousing sections 108, 112.

It should be appreciated that the hydraulic actuation may be reversedwhereby propulsion system 120 may be moved upstream in borehole 12. Inother words, propulsion system 120 can walk either forward, downstream,or backward, upstream in borehole 12. It also should be appreciated thatalthough propulsion system 120 is shown as being hydraulically actuated,it may also be operated electrically with power being provided by powertransmission conductor 43.

It should be appreciated that although the propulsion system 120 hasbeen described with two traction modules, the propulsion system 120 maybe configured with additional traction modules, such as three tractionmodules, depending upon the application.

Western Well Tool, Inc. manufactures a tractor having expandable andcontractible upstream and downstream packerfeet mounted on a hydraulicram and cylinder for self-propelling drilling bits. The Western WellTool tractor is described in a European patent applicationPCT/US96/13573 filed Aug. 22, 1996 and published Mar. 6, 1997,publication No. WO 97/08418, incorporated herein by reference.

Other propulsion systems may be adapted for use with the bottom holeassembly 30 of the present invention. Other types of tractors include aninchworm by Camco International, Inc., U.S. Pat. No. 5,394,951,incorporated herein by reference and by Honda, U.S. Pat. No. 5,662,020,incorporated herein by reference. Also robotic tractors are produced byMartin Marietta Energy Systems, Inc. and are disclosed in U.S. Pat. Nos.5,497,707 and 5,601,025, each incorporated herein by reference. Anothercompany manufactures a tractor which it calls a “Helix”. See also“Inchworm Mobility—Stable, Reliable and Inexpensive,” by AlexanderFerwom and Deborah Stacey; “Oil Well Tractor” by CSIRO-UTS of Australia;“Well Tractor for Use in Deviated and Horizontal Wells” by FredrikSchussler; “Extending the Reach of Coiled Tubing Drilling (Thrusters,Equalizers, and Tractors)” by L. J. Leising, E. C. Onyia, S. C.Townsend, P. R. Paslay and D. A. Stein, SPE Paper 37656, 1997, allincorporated herein by reference. See also “Well Tractors for HighlyDeviated and Horizontal Wells”, SPE Paper 28871 presented at the 1994SPE European Petroleum Conference, London Oct. 25-27, 1994, incorporatedherein by reference.

Referring again to FIG. 6, the steerable assembly 124 preferablyprovides three dimensional steering and may include either an adjustablecoupling, such as disclosed in U.S. Pat. No. 5,311,952, incorporatedherein by reference, or a variable eccentric adjustable diameter bladestabilizer. FIG. 6 illustrates a variable eccentric adjustable diameterblade stabilizer having a plurality of stabilizer blades 141 disposedazimuthally in slots around the mid-portion 143 of housing 106. Eachstabilizer blade 141 is mounted on one or more ramp members 145 integralwith housing 106 such that upon axial movement of stabilizer blade 141,ramp surfaces 145 cam blade 141 radially outward and into engagementwith the wall of borehole 12. Blades 141 may be variably and adjustablymoved radially outward by an electrically actuated screw 147 mountedadjacent the upstream end of blade 141 in housing 106. Electric screw147 is electrically connected to one or more of the electricalconductors 40 for actuation from the surface. A spring member 149 ismounted in the housing 106 at the downstream end of blade 141 forretracting blade 141 into the housing slot. Each of the stabilizerblades mounted on housing 106 are individually adjustable radiallywhereby the fulcrum at the center of housing 106 for bit 140 may bevaried to alter the trajectory of the bit in substantially anydirection. Eccentric blade stabilizers are described in U.S. Pat. Nos.3,129,776; 4,185,704; 4,388,974; and 5,423,389, each of these patentsbeing incorporated herein by reference.

If the steerable assembly 124 includes an adjustable coupling betweenhousing section 106, 112, shaft 116 articulates at articulation joint118. One type of adjustable coupling is disclosed in U.S. Pat. No.5,314,032, incorporated herein by reference. Power may be transmittedthrough propulsion system 120 through the articulation joint 118 bymeans of a constant velocity U-joint or a torsion rod. One type ofarticulation joint is shown in U.S. Pat. No. 5,527,220, incorporatedherein by reference. A titanium flex shaft may also be used. Steerableassembly 124 is preferably controlled from the surface although it maybe controlled downhole in bottom hole assembly 30.

Referring now to FIGS. 13-16, there are shown alternative embodimentsfor steering the bottom hole assembly . These are embodiments additionalto the surface controlled articulated (either mechanically,hydraulically or electrically) joint between the two traction modules aswas originally described.

Referring now to FIGS. 13 and 14, the bottom hole assembly 190 includesa drill bit 140 mounted on a downhole umbilical propulsion system 194.Propulsion system 194 includes a housing 196 having two traction modules198, 200 mounted adjacent each end thereof. Traction modules 198, 200have individually inflatable chambers 202 disposed between steel feet204 and housing 196. An independent valve 206 is provided for eachchamber 202 and can be inflated to an individual predetermined pressureso as to expand each chamber to individual extents on selected arcuateportions of the feet 204 thereby moving the housing 196 eccentricallywith respect to the borehole 12. As shown in FIGS. 13 and 14, thechambers 202 of the near bit traction module 198 are fully inflatedadjacent the low side 208 of the borehole 12 to raise the housing 196with respect to the low side 208 borehole 12 and the chambers 202 of thefar bit traction module 200 are fully inflated on the high side 210 ofthe borehole 12 to lower the housing 196 with respect to the low side208. This places an upward force on the bit 140 causing the bottom holeassembly 190 to build angle and incline the well path upwardly.Likewise, the inflation of the modules 198, 200 may be reversed to dropangle. It should also be appreciated that chambers 202 can beindividually inflated in a predetermined manner in each of the tractionmodules 198, 200 to change the inclination and azimuth of the well pathin any preferred three dimensional direction. This method can be used tosteer the bit 140 in any direction and does not require an articulatedjoint between the two traction modules 198, 200.

Referring now to FIGS. 15 and 16, the bottom hole assembly 212 includesa drill bit 140 mounted on a downhole umbilical propulsion system 214.Propulsion system 194 includes a housing having two housing sections218, 220 coupled together by an adjustable coupling 222 The output shaft116 includes an articulation joint 118. (See FIG. 6) The housing canhave an integral articulated joint for maximum bend or a limber flexjoint that allows for bending at that point in the housing. Standardconcentric traction modules 102, 104 mounted on housing sections 218,220, respectively, adjacent the outer end thereof. A steering assembly230 is disposed around adjustable coupling 222 between the two tractionmodules 102, 104. The steering assembly 230 includes a steering actuator232 having individual and independent either mechanical, hydraulic, orelectrical actuators 234 connected to a plurality of shafts 236. Thereare preferably four shafts 236. Shafts 236 extend through apertures 238in steering actuator 232 and are connected to individual actuators 234for each extending a shaft 236 a predetermined distance from steeringactuator 232. As the steering actuator 232 is actuated from the surface,it causes the housing between the two traction modules 102, 104 to bowthereby exerting a lateral force on the drill bit 140 in the samedirection as the extended shaft 236 in the steering actuator 232. Theshafts 236 can be individually extended in a predetermined manner by theindividual actuators 234 to change the inclination and azimuth of thewell path in any preferred three dimensional direction.

It is possible that the traction modules may rotate slightly in theopposite direction of the bit rotation due to reactive torque. Thedownhole umbilical propulsion system 120 includes integral counterrotation device 125 to automatically counter rotate the propulsionsystem 120 to maintain correct orientation of the bend angle such thatthe correct direction of the borehole trajectory is maintained.

The downhole umbilical propulsion system 120 contains an integralWOB/TOB (weight on bit and torque at bit) sensor. This sensor providesinformation to the surface computer which process the data and thenissues instructions to the propulsion system 120 such that the bit RPMand applied weight on the bit can be modified to optimize ROP (rate ofpenetration) and reduce bit bounce and bit balling. Flow rates and flowpressure can also be modified to improve ROP.

In operation, the propulsion system 120 is maintained in one orientationsuch that upon articulation between housing sections 108, 112 bysteerable assembly 124, there is a known inclination at the bit 140.Thus, propulsion system 120 does not rotate nor does it roll withinborehole 12 by design.

Propulsion system housing 106 includes aligned channels 142, 144 inhousing sections 108, 112, where an articulation joint 118 is required.However, this will depend upon the steerable assembly 124 being used.Note also that a flex joint may be used in place of the articulatedjoint 118. Also the articulated joint 118 can be smart (surfacecontrolled) or dumb (no control and it is just used to allow for maximumbend between the traction modules) much like a flex joint.

Resistivity antenna 122 is in two parts, a downstream antenna 146 and anupstream antenna 148 housed in channels 142, 144, respectively. Eachchannel 142, 144 is sealed to cover antennas 146, 148 and preventantennas 146, 148 from coming into contact with fluids. Antennas 146,148 are housed in channels 142, 144, respectively, so that antennas 146,148 do not break as housing 106 flexes during operation. Resistivityantennas 146, 148 and receivers have a combined overall length ofapproximately 12 feet. Thus, traction modules 102, 104 must be at least12 feet apart to allow room for antennas 146, 148. Resistivity antennas146, 148 can investigate formation depths of approximately 10 to 34inches from the propulsion system housing 106.

Resistivity antennas 146, 148 are flexible wires which are connected bya common connection that extends across articulation joint 118 and has adata transmission conduit connected to electronics section 110. The datafeed for the resistivity measured by antenna 122 is first transmitted tothe electronics section 110 and then transmitted to the surface. Aspreviously described, the antennas 146, 148, their common connection andthe related electronics package in electronics section 110 together formresistivity tool 121. It should be appreciated that although it ispreferred to locate resistivity antennas 146, 148 between tractionmodules 102, 104, resistivity antennas 122 may be located upstream oftraction module 104.

This formation data is then transmitted via fiber optic cables 42 fromelectronics section 110 to the surface where it is processed by thecontrols 21 to identify the formation properties immediately surroundingthe bottom hole assembly 30. The combination of resistivitymeasurements, gamma, inclination at bit all facilitate pay zone steeringfrom the surface.

Several companies manufacture a resistivity tool including Halliburton,Schlumberger, Dresser Sperry, Inc. and Baker Hughes. Resistivity toolsare also described in U.S. Pat. No. 5,318,138, incorporated herein byreference.

A gamma ray and inclinometer instrument package 130 is disposed forwardof downstream propulsion system 120 between propulsion system 120 anddrill stem 123 on which drill bit 140 is mounted. It is preferred thatthe gamma ray and inclinometer instrument package 130 be disposedforward of downstream propulsion system 120 so as to be as near to bit140 as possible. The gamma ray and inclinometer instrument package 130is a tool having a magnetometer and sensors for detecting the dynamicinclination and azimuth of drill bit 140. The gamma ray and inclinometerinstrument package 130 includes pay zone steering tools for guiding thetrajectory of the well path. The gamma ray and inclinometer instrumentpackage 130 is connected to the electronic section 110 by means of anelectromagnetic data transmission system, such as that described in U.S.Pat. No. 5,160,925, incorporated herein by reference, with the databeing transmitted to the surface through one or more of the datatransmission conduits 42 in composite umbilical 20.

The resistivity measurements from the resistivity tool 121, theinclination and azimuth measurements from the gamma ray and inclinometerinstrument package 130, and the tri-axial accelerometers are the primarymeasurements for geo-steering or pay zone steering of the well path.These measurements are processed at the surface to ensure the properdirection of the drilling of bit 140 or if necessary, to correct thedirection of the well path by means of the steerable assembly 124.

In the present invention, the downhole umbilical propulsion system 120is integral with the steerability of the bottom hole assembly 30 due tothe resistivity antennas 146, 148 being mounted on propulsion system 120and the gamma ray and inclinometer instrument package 130 being disposedbetween propulsion system 120 and bit 140. In the prior art, someformation sensors are located upstream of the steerable assembly bendangle as for example 10-50 feet from the bit, which affect the abilityto sense the need for course correction in time to avoid drilling intoproblem zones. By locating the steerability assembly 124 in thepropulsion system 120, the propulsion system 120 may be located veryclose to bit 140 and the bent sub of a conventional bottom hole assemblyis eliminated. Alternatively, the resistivity antenna 122 could bemounted above propulsion system 120.

Although resistivity tool 121 has been shown as being included withbottom hole assembly 30, it should be appreciated that a resistivitytool is not required to operate the drilling system 10 of the presentinvention. The gamma ray and inclinometer instrument package 130 canprovide adequate pay zone steerability without resistivity measurementsin many applications. Further, since the drilling system 10 of thepresent invention will often be used in existing wells, the existingwells will have previously been mapped and the coordinates of thebypassed hydrocarbon zones will have previously been determined suchthat a well plan can be designed with a geometric well path to thebypassed hydrocarbons without the need of their location through the useof resistivity or other pay zone steering sensors. The pay zonecapability gamma ray and inclinometer instrument package 130 will guidethe bit 140 along the pre-determined mapped well path.

In operation, the bottom hole assembly 30 is assembled including bit140, gamma ray and inclinometer instrument package 130, downholeumbilical propulsion system 120, steerable assembly 124, resistivitytool 121, electronics section 110, transmission 100, and power section90. The bottom hole assembly 30 is then connected to the lower end ofcomposite umbilical 120 to the top of the release tool 80. The bottomhole assembly 30 is lowered into the borehole 12 on composite umbilical20. One preferred method of deploying the composite umbilical 20 in thewell is to first deploy a 10,000 length of composite umbilical 20 andthen deploy individual 1,000 foot lengths connected together byconnector 50. Drilling fluids flow down the flowbore 46 of compositeumbilical 20, through power section 90, the flow bore 114 throughpropulsion system 120, through the bit 140 and back up the annulus 82 tothe surface. Where the power section 90 is a downhole positivedisplacement motor, turbine, or other hydraulic motor, the drillingfluids rotate the rotor within the stator causing the output shaft 116extending through the propulsion system 120 to operatively rotate bit140. The resistivity antenna 122 receives feedback from the formationand sends the resistivity data to the electronic section 110. Likewise,the gamma ray and inclinometer instrument package 130 provides data onthe surrounding formation and the inclination and azimuth near the bit140. The electrical conduit 40 in the composite umbilical 20 provideselectrical power to the electronic section and all downhole sensorsexcept the gamma ray and inclinometer instrument package 130 and is usedto power the power section 90 when the power section 90 is an electricmotor.

For additional information on directional drilling, see U.S. Pat. No.5,332,048; Introduction to Petroleum Production, Chapters 2 and 3,Volume I, by D. R. Skinner; “State of the Art in MWD” by theInternational MWD Society, Jan. 19, 1993; “Measurements at the Bit: ANew Generation of MWD Tools”, April/July 1993 issue of Oilfield Review;“Anadrill Directional Drilling People, Tools and Technology Put MoreWithin Your Reach” by Anadrill Schlumberger, 1991; “PredictingBottomhole Assembly Performance” by J. S. Williamson and A. Lubinski,IADC/SPE 14764, 1986; “Technical Data Sheet for Navigator” by BakerHughes Inteq, 1994; “An Underground Revolution, Integrated DrillingEvaluation and Logging” By Anadrill Schlumberger, 1995; “Ideal WellsiteInformation System” by Anadrill Schlumberger; “The Navigator SalesOrientation Manual” By Frank Hearn, John Hickey, Paul Seaton and LesShale; and “Navigator Reservoir Navigation Service” by Baker Hughes1996, all incorporated herein by reference.

The propulsion system 120 propels the bit 140 into the formation fordrilling the new borehole 12. The rate of penetration or feed iscontrolled from the surface. The only rotating portion of the bottomhole assembly 30 is the output shaft 116 and bit 140. The compositeumbilical 20 and the remainder of the bottom hole assembly 30 do notrotate within the borehole 12. Thus, the drilling system 10 of thepresent invention only operates in the sliding mode in that thecomposite umbilical 20 never rotates for purposes of drilling. Thesensors in the gamma ray and inclinometer instrument package 130, thetri-axial accelerometers and the resistivity tool 121 provide theoperator at the surface with the orientation, direction and location ofthe bit 140 and the proximity of the borehole 12 relative to the payzone in the formation. The propulsion system 120 may then be articulatedby steerable assembly 124 to properly direct the bit 140 in response tothe data from the directional and pay zone sensors. It should beappreciated that the bottom hole assembly 30 may be controlled by acontrol circuit, such as a microcontroller circuit in the controls 21 atthe surface, which receives downhole signals and data through the datatransmission conduits 42 in the wall of the composite umbilical 20,analyzes these signals and data, and then sends instructions downholethrough the data transmission conduits 42 to direct the downholeoperation. See for example U.S. Pat. No. 5,713,422, incorporated hereinby reference.

Referring again to FIG. 4, a jet sub 60 may be disposed between the endconnectors 56, 58 of connector 50. Jet sub 60 includes a plurality ofports 61 communicating with the flowbore 46 and a nozzle 63 in each port61 extending to exterior of jet sub 70 at an upstream angle. A valve 65is also disposed in each port 61 for controlling the passage of fluidthrough ports 61. Valves 65 may be controlled from the surface. As thecuttings from bit 140 travel up annulus 82, they may tend to concentratein the annulus 82 and fail to flow to the surface. Reverse jet sub 60allows hydraulic fluid to pass through nozzle 63 to form fluid jets toforce the cuttings up past the shoe of the cased borehole where frictionis reduced and the cuttings are allowed to flow to the surface. Reversejet subs 60 may be disposed at each connection 50 to sweep the cuttingsup the annulus so that they can be flowed to the surface.

It should be appreciated that although the bottom hole assembly 30 hasbeen described with only one downhole umbilical propulsion system 120,the bottom hole assembly may include more than one downhole umbilicalpropulsion system 120 and may consist of two or more downhole umbilicalpropulsion systems such as in tandem to provide additional power forpropelling the bit 140. Such downhole umbilical propulsion systems maycontain two or more traction modules depending upon the application.

It should further be appreciated that the bottom hole assembly 30 neednot be directed solely for use in drilling but may in fact be other welltools to perform other operations in a well. Such well tools include awell intervention tool, a well stimulation tool, a logging tool, adensity engineering tool, a perforating tool, or a mill.

The composite umbilical 20 is not required to withstand a great amountof tension or compression. As the drilling fluids pass down the flowbore46 and up the annulus 82, the drilling fluids provide a buoyancy tocomposite umbilical 20 thereby reducing the tension and compressionplaced on composite umbilical 20. Further, since composite umbilical 20does not rotate within the borehole, composite umbilical 20 is isolatedfrom any reactive torque from bottom hole assembly 30.

The composite umbilical 20 also has sufficient tensile and compressionstrength to withstand most extraordinary conditions during drilling. Forexample, if the bottom hole assembly 30 becomes stuck in the well, thecomposite umbilical 20 has sufficient tensile strength to withdraw thestuck bottom hole assembly 30 in most situations. Further, if the bottomhole assembly 30 is run into a producing well, the composite umbilical20 may be run in against the pressure of the producing well whichapplies compressive loads as the result of hydrostatic or formationpressures. This sometimes occurs in a workover well to be restimulatedto enhance production. The composite umbilical 20 will have internalpressure from the drilling fluids so as to balance the external wellpressure as well as adequate collapse strength.

The electronics used in the electronics section 110 are inexpensive ascompared to the electronic components of conventional bottom holeassemblies. Thus, even if the electronics were to degrade over timebecause of high temperatures, the bottom hole assembly 30 may beretrieved from the well and the electronic boards in the electronicsection 110 replaced or repaired.

Various types of data may be transmitted to the surface utilizing thedata transmission conduits 42 in the composite umbilical 20. Some of thetypes of data which may be transmitted to the surface includeinclination, azimuth, gyroscopic survey data, resistivity measurements,downhole temperatures, downhole pressures, flow rates, rpms of the powersection, gamma ray measurements, fluid identification, formationsamples, and pressure, shock, vibration, weight on bit, torque at bit,and other sensor data. The bottom hole assembly, for example, mayinclude a pressure sub for sensing the pressure in the annulus 82 ofborehole 12.

The data transmission conduit 42 is preferably fiber optic cable. Fiberoptic cable has a very large band width allowing the transmission oflarge amounts of data which then can be processed by powerful computersat the surface. Using fiber optic cable, the data transmission rates arefast and a greater amount of data can be transmitted. By processing thedata at the surface, the bottom hole assembly 30 is much less expensiveand is much more efficient. The ability to have a high data transmissionrate to the surface allows the elimination of most of the electronics ofprior art bottom hole assemblies. It also enhances the reliability oftransmission of the data to the surface since pulsing the data throughthe mud column is eliminated.

The electrical conductors 40 in composite umbilical 20 allow more powerto be transmitted downhole. This allows the resistivity measurements toreach deeper into the formation. Further, an alternator or a batterysection is no longer required in the bottom hole assembly to power allexcept gamma ray and inclinometer instrument package 130. Greater powerfrom the surface can also be used to transmit electrical current intothe formation to enhance resistivity measurements by resistivity tool121.

It should be appreciated that the composite umbilical 20 and propulsionsystem 120 may be used to convey various well apparatus into the welland be used with bottom hole assemblies having other applications in thedrilling, completion and production of wells. The composite umbilical 20and propulsion system 120 may be used during drilling to move in and outof the borehole such well apparatus as an electric motor, turbine, vane,or positive displacement drilling motor, various types of sensors tomeasure three dimensional position in space, a member for displacingformation such as a bit or jets, a caliper log (sonic or mechanical), adirectional kickff device such as whipstock, a casing mill, a casingexit system (chemical or explosive) or other downhole tool used indrilling. The composite umbilical 20 and propulsion system 120 may alsobe used with various drilling performance sensors such as gamma,resistivity, magnetic resonance (MRI), sonic, neutron density,temperature, pressure, formation pressure, or other downhole parameter.The composite umbilical 20 and propulsion system 120 may further be usedwith drilling performance sensors such as weight on bit, torque on bit,rate of penetration, pipe pressure, annulus pressure, shock andvibration, motor rpms, differential pressure across the motor, or otherperformance parameters. Various steering apparatus may be used with thecomposite umbilical 20 and propulsion system 120 such as a fixed bend inor above the motor, a fixed bend in or above the motor with an orienter,an adjustable bent sub in or above the motor with an adjustableorienter, a three dimensional or lesser steering system, one or moreback flow check valves, a circulating sub, a quick disconnect sub, acasing collar locator, batteries, an electric turbine, electronics,stabilizers or other device used for steering the bottom hole assembly.The composite umbilical 20 and propulsion system 120 may also be usedwith production equipment such as a downhole pump, an open hole packer,a cased hole packer, a sand screen, a pressure control downhole valve, aperforated liner, a perforating gun, or other device used to produce thewell. The composite umbilical 20 and propulsion system 120 may furtherbe used with workover equipment or for treating the formation such ascasing scrapers, jet cleaning tools, acids and other well treatmentfluid systems, zonal treatment fluid systems or other devices forworkover or treating the well. The composite umbilical 20 and propulsionsystem 120 may also be used to convey a well intervention tool, a wellstimulation tool, a density engineering tool or a logging tool as forexample. The above lists of well service and maintenance tools areintended to be exemplary and not all inclusive.

Referring now to FIGS. 8 and 9, the composite umbilical 20 may be usedwith a bottom hole assembly 150 for cutting a sidetrack window in anexisting cased borehole to drill a new borehole into a bypassedhydrocarbon zone. FIG. 1 illustrates a well for the use of bottom holeassembly 150 to remove a section of the existing casing to allow exit ofpropulsion system 120, for drilling the new borehole 12.

Referring now to FIG. 8, bottom hole assembly 150 is connected to thedownstream end of composite umbilical 20 by release tool 80. The bottomhole assembly 150 includes a power section 90, a transmission 100, anelectronics section 110, and a downhole umbilical window cuttingassembly 160. It should be appreciated that the bottom hole assembly 150does not include a bit and may not require power section 90. Theelectronics section 110 is still useful in transmitting data to thesurface on downhole parameters such as temperature and pressure.

Cutting assembly 160 includes an upstream transaction module 102 and adownstream traction module 104. Propulsion system 160 includes atemplate 164 mounted on hydraulically actuated pistons 165, 167 disposedin housing 163 for moving template 164 between an extended position incontact with the wall of cased borehole 14 and a retracted positionadjacent housing 163 as shown in FIG. 8.

It should be appreciated that depending upon the application and thewell, a propulsion system may or may not be required with bottom holeassembly 150. If self-propulsion is not required, traction modules 102,104 would merely be used to provide a stable platform for the cuttingoperation of the window. The expanded traction modules 102, 104 providean absolute stabilized platform for setting the template 164 and thencutting around the template 164 in a preferred shape for the window 170.

As best shown in FIG. 9, template 164 has a perimeter 166 in thepredetermined shape of window 170 to be cut in the wall 172 of casedborehole 14. One or more jet nozzles 168 are mounted on the end of aflexible hose providing jets of water mixed with a gas such as nitrogenor carbon dioxide supplied from the surface. It should be appreciatedthat the cutting method of the present invention is not be limited tofluid. For example, a high temperature cutting apparatus or other methodmay be used. Nozzle 168 is mounted on a track 169 having a rotating gear171 for moving nozzle 168 in a spiral motion on housing 160 and along aspiral path 174 adjacent the perimeter 166 of template 164 to cut thewindow 170 in the wall 172 of casing 14. Nozzle 168 may be poweredeither hydraulically or electrically along the track 169 in a spiralfashion, such as path 174, to cleanly cut the window along its perimeter166 by cutting multiple parts 176 of the cased borehole 14 inside thetemplate 170. The parts 176 of casing 12 are then removed magneticallyby electromagnets 178 disposed on housing 163.

In operation, bottom hole assembly 150 is moved into position adjacentthe location for the window 170. Traction modules 102, 104 are expandedinto engagement with the wall 172 of casing 12 thus providing a stableplatform for the cutting of window 170. The hydraulic pistons 165, 167on housing 163 are actuated to move the template 164 against the insideof wall 172 of casing 12. The template 164 is maintained in position bythe pressure applied thereto by hydraulic pistons 165, 167. Gears 171mounted on the track 169 of housing 160 are actuated electrically andfluid mixed with gas is pumped from the surface through compositeumbilical 20 and through jet nozzle 168. As the gears 171 move nozzle168 in a spiral fashion along track 169 and inside the template 164,parts 176 of casing 172 are cut free and are retracted byelectro-magnets 178. Once the nozzles 168 have completed cutting all ofthe parts 176 of casing 12 to form the window, traction modules 102, 104are released and the bottom hole assembly 150 is retrieved from thecased borehole 14. The result is a cleanly cut window of uniform shapeas shown in FIG. 9.

Although bottom hole assembly 150 has been described using a waterfrozen by a gas for cutting the window 170, it should be appreciatedthat bottom hole assembly 150 may be fitted with other means for cuttingthe window 170 such as explosive charges, chemical nozzles, or ice usingnitrogen or other gas or liquid. Other means include percussiondrilling, an acetylene torch, or arcing.

Referring now to FIG. 10, after the bottom hole assembly 150 has beenremoved from the well 14, a tubular member 180, having a seal flange 182with the shape and dimensions of the window 170, is mounted on bottomhole assembly 150, or like assembly, and run into the borehole 14. Uponpositioning assembly 150 adjacent the window, and after expandingtraction modules 102, 104 into engagement with the wall 172 of thecasing 14, the hydraulic actuators, similar to actuators 165, 167, areactuated to properly orient the tubular member 180 and pass the tubularmember 180 into the window 170. The seal flange 182 is then abuttedaround the periphery 166 to form a seal around the window 170 in casing14. The seal flange 182 provides a mechanical sealed junction 184 at thewindow 170 for receiving a bottom hole assembly, such as bottom holeassembly 30, for drilling new borehole 12. Upon completing the drillingof the new borehole 12, a production string may be lowered through thetubular member 180 and seal flange 182 and into the new borehole 12.

Alternatively, a completion string may be run into the borehole 12 andthrough the bore of tubular member 180. The casing can then be cementedin the new borehole 12. The new casing in the new borehole 12 keeps thenew borehole 12 open, allow for subsequent treatments of the formationand to prevent the borehole from collapsing during production. It shouldbe appreciated that if a quick production of the bypassed formation isdesired, the upper end of the casing may project into the cased boreholeand an external casing packer set around the upper end to seal off theexisting cased borehole 14. Frequently the production from the existingpay zones and the bypassed pay zones are commingled above the externalcasing packer and pass up the cased borehole to the surface.

It is possible to use composite umbilical 20 as the production string inthe new borehole 12. Composite umbilical 20 can be tied back to theexternal casing packer or sealed at the casing exit point and extend tothe surface.

Utilizing bottom hole assembly 150 allows the drilling system 10 to tripinto the borehole 14 and retract from the borehole 14 quickly. Oneobjective of the drilling system 10 of the present invention is toproduce the bypassed formations quickly and economically because oftheir limited producing life.

It should also be appreciated that composite umbilical 20 may be usedfor perforating the well. For example, after bottom hole assembly 150has been removed from the well 12 and the well has been cased, aperforation joint may be attached to the downhole end of compositeumbilical 20 and run down into the new borehole 12. The perforationjoint can then be detonated to perforate the borehole 12 for production.The composite umbilical 20 can then be used as production tubing.Screens can also be run on the downstream end of composite umbilical 20.

Another application of the bottom hole assembly of the present inventionis testing while drilling. The bottom hole assembly is lowered into thewell and located adjacent the formation to be tested. The upper andlower traction modules on the bottom hole assembly are used to isolatethe production zone in the cased borehole. The data is then gathered andprocessed, typically for testing formation pressures. Often samples arecollected for retrieval to the surface.

The bottom hole assembly must be especially rugged to withstand theextremely harsh drilling environment.

The downhole umbilical propulsion system of the present invention mayinclude other applications. These include the conveyance of conventionallogging tools and the pulling of casing or a completion string into theborehole, as for example.

Referring now to FIGS. 11 and 12, it is still preferred to use steel forcasing the new borehole. Steel has a greater absolute tensile andcompressive strength and is more elastic than present day compositetubing. Also, steel is able to withstand the temperature gradientswithin the producing well as well as other environmental conditions thatexist in the producing well. Steel casing is also able to withstand themany sheer forces of a producing well. Therefore, the drilling system 10preferably uses the bottom hole assemblies on composite umbilical 20 fordrilling the borehole and then steel casing is lowered into the newborehole for completing the well.

Since it is the objective of the drilling assembly 10 of the presentinvention to eliminate the requirement of a rig, a completion assembly240 is shown in FIGS. 11 and 12 which requires no rig. Completionassembly 240 includes a pipe handling system 242, a casing elevator 244,casing tongs 246, and casing rams 250. The pipe handling system 242picks up individual casing joints in the horizontal position shown at248 and then moves individual casing joints into an intermediateposition at 252 and then to an upright position 253. The new joint isthen positioned horizontally over the wellhead 254. In the verticalposition over wellhead 254, the hydraulically controlled casing elevator244 grabs the new joint of pipe for alignment with the upper end of thecasing string projecting from wellhead 254. Tongs 246 are mounted on theframe of hydraulic casing rams 240 for threading the new casing jointonto the upper end of the casing string in the borehole.

Referring now to FIG. 12, the casing rams 250 support the casingelevator 244 by means of a top bowl 256 and a bottom bowl 258. Bowls256, 258 include slips for suspending the casing string. The casingstring passes through the slips in bowls 256, 258 which support and grabthe casing. The casing rams include four rams 260 for pushing downwardlyon the new casing joint and casing string and thus into the newborehole. One type of casing rams are manufactured by R. L. Gilstrap Co.of Oklahoma City. See “The Wellhead CasingJac for Extra Pipe PullingPower” by R. L. Gilstrap Co., incorporated herein by reference. Afterthe new joint of pipe is threadingly connected to the casing string, itis jacked into the borehole using the hydraulic casing jacks 252. Thecompletion system 240 also includes conventional cementing of the newcasing in the well.

The completion system 240 has several advantages over the prior art. Ascan be seen, no rig is required for installing the casing string in thenew borehole. Further, the completion system 240 may be operated by asfew as two men. Also, the casing rams 250 have the ability to pull thecasing out of the well and have sufficient power to overcome thefriction and drag of the casing against the cased borehole. Further, thecasing rams 250 have the ability to push the casing string into thewell. Conventional rigs do not have such an ability and rely upon theweight of the casing using gravity and or rotation or reciprocating toinstall the casing string in the well.

It should be appreciated that the present invention may be used with aconventional rig or may include the reduced use of a conventionaldrilling rig. For example, an operator use a conventional rig to drillboreholes for the conductor casing and then release the rig for use onother wells.

While a preferred embodiment of the invention has been shown anddescribed, modifications thereof can be made by one skilled in the artwithout departing from the spirit of the invention.

What is claimed is:
 1. A system for conveying a well apparatus in a well, comprising: a composite umbilical having a conductor disposed in a wall of said composite umbilical; a propulsion system attached downhole to said composite umbilical; and said composite umbilical including a tube which is non-isotropic and which carries axial loads placed on said composite umbilical.
 2. A system for conveying a well apparatus in a well from the surface, comprising: a composite umbilical having a flowbore and forming an annulus in the well to circulate fluids through the flowbore and annulus; a propulsion system attached downhole to said composite umbilical and powered by the circulating fluids; and said composite umbilical including a tube having a modulus of elasticity which is not the same in all axes.
 3. The system of claim 2 further including another propulsion system in tandem with said propulsion system.
 4. The system of claim 2 wherein said composite umbilical has a central axis and includes a woven or braided conductor disposed in a wall of said composite umbilical and extending around said central axis.
 5. The system of claim 2 further including a release adjacent an end of said composite umbilical.
 6. The system of claim 2 wherein said propulsion system includes a sensor measuring drilling parameters, said measurements being transmitted real time to a control at the surface, said control processing said measurements and transmitting instructions to said propulsion system.
 7. The system of claim 2 wherein said propulsion system includes a control which determines the movement of the well apparatus.
 8. The system of claim 7 wherein said control communicates with the surface.
 9. The system of claim 7 wherein said control is closed loop.
 10. The system of claim 2 wherein said composite umbilical includes a plurality of lengths of a composite pipe, each length including an inner liner, a plurality of load carrying layers around said liner, at least one electrical conductor and at least one data transmission conductor extending through a wall of each said length; at least one end connector disposed on ends of adjacent lengths and receiving one end of said liners, load carrying layers, electrical conductor and data transmission conductor; and said end connector having conductor connectors for connecting said electrical conductors and said data transmission conductors and having seals to seal said flowbore through said composite umbilical.
 11. The system of claim 2 further including a control at the surface receiving and sending signals downhole to and from said propulsion system and the well apparatus via a conductor in a wall of said composite umbilical.
 12. The system of claim 2 further including: a control at the surface controlling the drilling of the well; said composite umbilical having a data transmission conduit coupled to said control; the well apparatus including a drill bit coupled to said propulsion system for drilling a borehole in the well; a steerable assembly coupled to said propulsion system and said data transmission conduit; an orientation assembly coupled to said propulsion system and sending signals through said data transmission conduit to said control; said steerable assembly and propulsion system receiving signals from said control; said steerable assembly adapted to move said drill bit three dimensionally within the borehole in response to said signals received by said steerable assembly; and said propulsion system adapted to move said drill bit upstream or downstream within the borehole in response to said signals received by said propulsion system.
 13. The system of claim 12 further including a magnetometer and an inclinometer which provide representative signals of the borehole's radial orientation and inclination for transmission to said control.
 14. The system of claim 2 wherein said composite umbilical includes load carrying layers.
 15. The system of claim 14 further including a conductor embedded in said load carrying layers, said conductor being embedded linearly, wound spirally or braided among said layers.
 16. The system of claim 15 wherein said conductor conducts two-way communications with the surface.
 17. The system of claim 16 wherein said conductor is multi-plexed to conduct two-way communication through a single conductor.
 18. A system for conveying a well apparatus in a well, comprising: a composite umbilical having a conductor disposed in a wall of said composite umbilical; a propulsion system attached downhole to said composite umbilical; and said composite umbilical including a tube having a modulus of elasticity which is not linear and having a yield strain which allows said tube to withstand loads placed on said composite umbilical.
 19. A system for conveying a well apparatus in a well, comprising: a composite umbilical; a propulsion system attached downhole to said composite umbilical; and one or more sensors being housed within a wall of said composite umbilical.
 20. A system for conveying a well apparatus in a well, comprising: a composite umbilical for supplying fluids downhole in the well; a propulsion system attached downhole to said composite umbilical; said composite umbilical including a tube engineered to cause said composite umbilical to achieve substantially neutral buoyancy in the fluids in the well; said tube having a modulus of elasticity which is not the same in all axes.
 21. A system for conveying a well apparatus in a well, comprising: a composite umbilical for supplying fluids downhole in the well; a propulsion system attached downhole to said composite umbilical; said composite umbilical being engineered to cause said composite umbilical to achieve substantially neutral buoyancy in the fluids in the well; one or more sensors being housed within a wall of said composite umbilical.
 22. A system for conveying a well apparatus in a well from the surface, comprising: a composite umbilical having a flowbore and forming an annulus in the well to circulate fluids through the flowbore and annulus; said composite umbilical having an energy conductor disposed in a wall of said composite umbilical; a propulsion system attached downhole to said composite umbilical; said composite umbilical including a tube having a modulus of elasticity which is not the same in all axes; said propulsion system being powered by the circulating fluids and being a part of a bottom hole assembly; and said energy conductor supplying power to said bottom hole assembly.
 23. The system of claim 22 wherein said bottom hole assembly includes a power assembly powered by the circulating fluids and includes a three dimensional steerable assembly.
 24. The system of claim 22 wherein said bottom hole assembly further includes an integral counter rotation mechanism.
 25. The system of claim 22 wherein said bottom hole assembly further includes a resistivity tool.
 26. The system of claim 22 wherein said bottom hole assembly further includes a gamma ray and inclinometer assembly.
 27. The system of claim 22 wherein said bottom hole assembly further includes an NMR magnetic resonance imaging tool.
 28. The system of claim 22 further including a transmission disposed downstream of a downhole motor.
 29. The system of claim 22 further including a gamma ray and inclinometer instrument assembly.
 30. The system of claim 22 further including a resistivity tool.
 31. The system of claim 22 wherein said bottom hole assembly includes a logging while drilling sensor.
 32. The system of claim 22 wherein said bottom hole assembly includes a magnetometer and at least one sensor detecting dynamic inclination and azimuth of said well apparatus.
 33. The system of claim 22 wherein said bottom hole assembly includes a power assembly controlled from the surface.
 34. The system of claim 22 wherein said bottom hole assembly further includes sensors measuring data relating to parameters and characteristics of the well, said data being transmitted to the surface through a data conductor.
 35. The system of claim 34 wherein said sensors measure data selected from the group consisting of operating pressures, operating temperatures, annulus pressures, formation pressures, fluid identification, geomagnetic, seismic, sonic, magnetic resonance, gyroscopic surveying, inclination, azimuth, porosity, and density.
 36. The system of claim 22 wherein said bottom hole assembly includes a formation measuring tool.
 37. The system of claim 36 wherein said formation measuring tool includes an electronics package and instrumentation package collecting data on drilling measurements, logging, and geological steering.
 38. The system of claim 37 further including a control at the surface receiving said data on measurement, logging and geological steering, and processing said data to identify formation properties immediately surrounding said bottom hole assembly.
 39. The system of claim 22 further including a control circuit at the surface communicating with said bottom hole assembly and sending commands to said bottom hole assembly.
 40. The system of claim 39 wherein said control circuit receives downhole information, analyzes said information and sends commands to said bottom hole assembly to direct downhole operations.
 41. The system of claim 40 wherein said downhole information is selected from the group consisting of inclination, azimuth, gyroscopic survey data, resistivity, temperatures, pressures, flow rates, gamma ray measurements, fluid identification, formation samples, magnetic resonance (MRI), sonic, neutron density, formation pressure, shock and vibration of the well apparatus, weight on bit, torque on bit, rate of penetration, revolutions per minute, and differential pressures.
 42. The system of claim 22 further including a control circuit exchanging signals with a steerable assembly and a prime mover.
 43. A system for use in a well from the surface, comprising: a composite tube having fibers in a predetermined orientation bonded in a matrix; said composite tube having a modulus of elasticity which is not the same in all axes and which withstands axial loads; said composite tube including a liner and a plurality of conductors disposed between said liner and said fibers; and a propulsion system attached downhole to said composite tube and conveying a well apparatus, one of said conductors supplying power to said well apparatus.
 44. The system of claim 43 wherein said well apparatus is selected from the group consisting of an electric motor, turbine, vane, positive displacement drilling motor, a sensor to measure three dimensional position in space, a member for displacing formation, an acoustic or mechanical caliper log, a whipstock, a casing mill, and a casing exit system.
 45. The system of claim 43 wherein said well apparatus is a production tool selected from the group consisting of a downhole pump, an open hole packer, a cased hole packer, a sand screen, a pressure control downhole valve, a perforated liner, and a perforating gun.
 46. The system of claim 43 wherein said well apparatus is a workover tool.
 47. The system of claim 43 wherein said well apparatus is a formation treatment tool selected from the group consisting of a casing scraper, a jet cleaning tool, a well treatment fluid assembly, and a zonal treatment fluid assembly.
 48. The system of claim 43 wherein said well apparatus is a well intervention tool, a well stimulation tool, a density tool, a perforating tool, a mill or a logging tool.
 49. The system of claim 43 for use in a cased well wherein said well apparatus is a cutting member to cut a window in the cased well to allow said system to exit the cased well.
 50. A system for conveying a well apparatus through a wellbore having wellbore fluids, comprising: a composite umbilical having a conductor disposed in a wall of said composite umbilical; a propulsion system attached downhole to said composite umbilical; and said composite umbilical having a density substantially the same as that of the wellbore fluids and a tube having a modulus of elasticity which is,not the same in all axes.
 51. The system of claim 50 wherein said density of said composite umbilical is a specific gravity in the range of 0.99 to 2.9 grams per cubic centimeter.
 52. The system of claim 50 wherein said tube is specifically engineered to be substantially buoyant in the wellbore.
 53. The system of claim 50 wherein said conductor is disposed between layers of fibers making up said tube.
 54. The system of claim 50 wherein said conductor is wound at a predetermined angle in said composite umbilical.
 55. The system of claim 50 wherein said tube is constructed of layers of wound fibers.
 56. The system of claim 55 wherein said fibers are oriented in different directions.
 57. The system of claim 55 wherein said fibers are engineered to provide a modulus of elasticity in an axial direction and yield stress which produces a spoolable composite umbilical.
 58. A system for conveying a well apparatus, comprising: a composite tube made of oriented layers of fibers in a matrix and including a liner and a plurality of conductors disposed between said liner and said fiber layers; said composite tube having a yield strain which allows said composite tube sufficient bending to be spooled onto a spool; said composite tube having a modulus of elasticity which is not the same in all axes; and a propulsion system attached downhole to said composite tube adapted for attachment to the well apparatus.
 59. The system of claim 58 wherein said yield strain is at least 0.01818.
 60. The system of claim 58 wherein said composite tube has a modulus of elasticity in an axial direction and a yield stress, said yield strain being a ratio of said yield stress to said modulus of elasticity.
 61. The system of claim 60 wherein said modulus of elasticity in the axial direction is in the range of 0.5 to 5.0 million psi.
 62. The system of claim 60 wherein said modulus of elasticity in an axial direction is determined by dividing the yield strain into the yield stress required for said composite tube to be engineered for a particular well.
 63. The system of claim 60 wherein said modulus of elasticity in an axial direction is at least 1.43 million psi.
 64. The system of claim 60 wherein said yield stress is at least 26,000 psi.
 65. A system for conveying a well apparatus through a wellbore having wellbore fluids, comprising: a composite tube made of oriented layers of fibers in a matrix and including a liner and a plurality of conductors disposed between said liner and said fiber layers; said composite tube having a conductor disposed in a wall of said composite tube and having a modulus of elasticity which is not the same in all axes; said composite tube having a yield strain, modulus of elasticity in an axial direction, and a yield stress, said modulus of elasticity in the axial direction being determined by dividing the yield strain into the yield stress required for said composite tube to be spoolable; and a propulsion system attached downhole to said composite tube.
 66. The system of claim 65 wherein said composite tube has a density substantially the same as that of the wellbore fluids.
 67. The system of claim 65 wherein said propulsion system is powered by the circulating fluids.
 68. A system for drilling a wellbore using drilling fluids having a specific gravity between 8.4 and 12.5 pounds per gallon, comprising: a composite umbilical having a conductor disposed in a wall of said composite umbilical and a tube having a modulus of elasticity which is not the same in all axes; said composite umbilical having a density substantially the same as that of the drilling fluids; and a propulsion system attached downhole to said composite umbilical applying a pull force on said composite umbilical between zero and 14,000 pounds depending upon the specific gravity of the drilling fluids.
 69. The system of claim 68 wherein said propulsion system is powered by the circulating drilling fluids. 